Gas Lift Workshop Gas Lift Workshop Doha – – Qatar Qatar Doha 4- -8 February 2007 8 February 2007 4 Gas Lift Optimisation of Gas Lift Optimisation of Long Horizontal Wells Long Horizontal Wells by Juan Carlos Mantecon 1
Long Horizontal Wells • The flow behavior of long horizontal wells is similar to pipelines (well horiz section) + riser (vertical section) • Dynamic Simulation techniques offer the best solution: – Slugging flow predictions – Multiple inflow points performance relationship – Limited validity of steady state techniques 2
Well Modelling – Horizontal-Vertical Wells IPR 3
Well Modelling - Horizontal Wells PI • Horizontal well PI is is inversely proportional to ß. • The impact of ß increases as the thickness of the reservoir increases (ßh) 4
Well Modelling - Horizontal vs. Vertical PI • A Steady State Equation – assumes equal drainage areas 5
Well Modelling – IPR Dynamic Simulation techniques • Lateral wells with long horizontal wellbores require multiple inflow points and corresponding PIs • Normally PI/m (or k thicknes) is available, and the PI for each section can be roughly estimated by multiplying the PI/m with the section length. • Building the model using a too fine grid can result in long simulation time and too many inflow point (reservoir data) 6
Potential Problems for Stable Multiphase Flow • Inclination / Elevation • “Snake” profile • Risers • Rate changes • Condensate – Liquid content in gas • Shut-in / Start up 7
Potential Problems for Stable Multiphase Flow Flow Regime Map - Inclination: Horizontal Measured & calculated SEPARATED DISTRIBUTED 8
Potential Problems for Stable Multiphase Flow Pressure impact on Pressure impact on Inclination impact on flow flow regime flow regime regime Vertical flow Horizontal flow BUBBLE BUBBLE BUBBLE BUBBLE BUBBLE SLUG FLOW SLUG FLOW SLUG FLOW SLUG FLOW 90 bar 90 bar SLUG FLOW 45 bar 45 bar Down Down ANNULAR 20 bar 20 bar Horiz. Horiz. STRATIFIED STRATIFIED Up Up STRATIFIED STRATIFIED Slug flow area decreases with increasing pressure Slug flow area increases with increasing upward inclination 9
Potential Problems for Stable Multiphase Flow Shut-In - Restart Rate Changes – Liquid redistributes due to – Pipe line liquid inventory decreases gravity during shut-in with increasing flow rate – On startup, slugging can – Rate changes may trigger slugging occur as flow is ramped up • Shut-In - Restart – Liquid redistributes due to gravity during shut-in Initial amount – On startup, slugging can occur as flow is ramped up Liquid Inventory A-Liquid Distribution After Shutdown Amount removed Final gas amount liquid Flowrate Gas Production R ate B-Gas and Liquid Outlet Flow 10
Hydrodynamic Slugging • Two-phase flow pattern maps indicate hydrodynamic slugging, but pipe 1 pipe 2 pipe 3 3 1 2 a.-terrain effect and slug-slug interaction Slug Length – slug length correlations are quite uncertain – tracking of the development of the Frequency individual slugs along the pipeline is necessary to estimate the volume of the b.-slug distribution liquid surges out of the pipelines 11
• Riser-Induced Sluging Pigging-405.plt A. Slug formation C. Gas penetration • Terrain Slugging Liquid flow accelerates Liquid seal – A: Low spots fills with liquid and flow is blocked – B: Pressure builds up B.Slug production D. Gas blow-down behind the blockage Gas surge Pressure build-up releasing high pressure C&D: When pressure – Equal to static liquid head becomes high enough, gas blows liquid out of the low spot as a slug For subsea and deepwater, the fluid behavior in the flowline and risers may actually dictate the artificial lift method, not the wellbore environment itself. 12
Slug Mitigation Method • Increase GL gas rate • Reduction of flowline and/or riser diameter • Splitting the flow into dual or multiple streams • Gas injection in the riser • Use of mixing devices at the riser base • Subsea separation (requires two separate flowlines and a liquid pump • Internal small pipe insertion (intrusive solution) • External multi-entry gas bypass • Choking (reduce production capacity) • Increase of backpressure • External bypass line • Foaming 13 A 20 km, 16” Dubar-Alwyn flowline, riser depth 250 m
Gas Lift Stability Well Modelling - Horizontal Wells • H-wells allow reduced drawdown pressure, thereby maintaining the reservoir pressure above the bubble point for longer periods of time, thus reducing GORs and improving recovery • H-wells producing below bubble point pressure can act as downhole separators – leading to slug flow • well instability occurs in long horizontal sections with upward- downward slopes, when liquid accumulates at the low points • Flow is suspected to be channeling outside the liner? 14
Well Modelling - Horizontal Wells - ER 15
Well Modelling - Horizontal Wells - ER 16
-mixture – gas – oil Green Blue Red Well Modelling - Horizontal Wells - ER 17
Gas Lift Stability Gas Lift Well Stability • Conventional Design (unloading valves) - the well instability is dampened due to multi-point injection. • Single point system (orifice) - there is a minimum surface injection rate required for the orifice to maintain sufficient annular backpressure (i.e. casing pressure consistently higher than the flowing tubing pressure) for continuous downhole gas injection. • This minimum injection rate is a function of orifice size and flowing tubing pressure (wellhead pressure, PI, reservoir pressure, watercut, etc) 18
Downhole & Surface Orifice Interaction 19 (Flow Stability)
Interaction Between Downhole & Surface Orifice If gas injection is not critical... Casing heading m ay happen To thoroughly elim inate casing heading, m ake the gas injection critical 20
Interaction Between Downhole & Surface Orifice Is the well unconditionally stable if gas injection is critical? Replace the orifice with a venturi 21
Density Wave Instability Because the gas-injection rate is constant, any variation in liquid inflow into the wellbore will result in a density change in Stability map (L=2500m, PI=4e -6 kg/s/Pa, P sep =10bara, 100% choke opening, ID=0.125m) the two-phase mixture in the tubing. The mixture-density change results in a 1,25 change in the hydrostatic pressure drop. 1,20 1,15 The mixture-density change travels along 1,10 the tubing as a density wave. 1,05 1,00 Density wave instability can occur! 0,95 0,90 Gas injection rate (kg/s) 0,85 0,80 0,75 � Increasing reservoir pressure and gas 0,70 injection rate increases stability. 0,65 0,60 � Increasing well depth, tubing diameter, 0,55 PI and system pressure decreases 0,50 0,45 stability 0,40 0,35 � Instability occurs only when 0,30 0,25 − P P 0,20 < R sep 1 0,15 ρ gL 0,10 l 0,05 0,00 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230 240 250 260 270 280 290 300 310 P R -P sep (bar) SPE 84917 Two-phase vertical flow under gravity domination often is unstable, particularly in gas lift wells . 22
Subsea-Deppwater Gas Lift Issues • Zero Intervention Philosophy • Single Point Injection • Understanding the Stability Issues • Using Dynamic Simulation Techniques 23
Single Point Injection Using Orifice Advantages • higher reliability than conventional completion using live valves • meets “zero intervention” philosophy set for subsea developments • fewer expensive GL mandrels required (less relevant) • removal of moving parts or parts that could leak • eliminate risk of incorrect pressure settings on bellows 24
Single Point Injection Using Orifice Disadvantages • requires a minimum gas injection rate for well stability • requires a higher injection pressure • valve erosion becomes an issue • operating valve will have to be set higher in the well (less production rate) • a well with only one mandrel will require a major well intervention should the operating valve have a problem • less flexible design 25
Gas Lift Stability – Horizontal Wells • The primary cause of wellbore and flowline slugging is that the superficial gas velocity is too low. The addition of gas lift gas increases the superficial gas velocity and changes the multiphase flow to a more stable flow regime. • Long horizontal sections give large volumes of gas and fluid which may influence each other and produce pressure variations in the wellbore and pressure fluctuations in the gas lift injection line. • Condensation of water in GL injection flowline could not only cause erosion of GLVs but reduce the GL efficiency by injecting also fluids – unexpected GLR. 26
Gas Lift Stability – Subsea Production System � Use Dynamic Simulation techniques – added benefit of flow assurance analysis. � When the cause of slugging flow and the severity is known, changes in design and/or producing conditions can mitigate or eliminate slugging and optimise production � Evaluate optimal single point injection: � Downhole � Wellhead � Base of riser � Downhole: If max. injection pressures already pre- determined, then injection depth variable. If not, injection depth in wellbore fixed as deep as possible, above 60 degree deviation. No limit for remote GLVs. 27
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